Presented below is background information on certain aspects of the present invention as they may relate to technical features referred to in the detailed description, but not necessarily described in detail. The discussion below should not be construed as an admission as to the relevance of the information to the claimed invention or the prior art effect of the material described.
Much of the world's electricity is generated by coal power plants. These plants vent ˜800 g of CO2 to the atmosphere for every kilowatt of electricity produced. These emissions are a major contributor to global warming. Natural gas is increasingly being used to replace coal, particularly in the United States, where the development of directional drilling and hydraulic fracturing has produced a large supply of low-cost gas. Natural gas power plants vent ˜400 g of CO2 to the atmosphere for every kilowatt of electricity produced, so switching fuels from coal to natural gas cuts CO2 emissions in half. However, longer-term, the emissions of natural gas power plants will also need to be controlled if global warming targets are to be met.
A variety of technologies are being developed to separate CO2 from power plant flue gas so the CO2 can be sequestered. Amine absorption is the leading technology but is costly, produces its own atmospheric emissions, requires careful operation and maintenance, and has a very large footprint. Membrane technology is also being developed and has many benefits, including lower capital and operating costs, modular construction, small footprint, no emissions and no changes to the power plant steam cycle are required. However, the technology is not as developed as amine, although demonstration units processing up to 20 tons CO2/day have been built.
In U.S. Pat. No. 7,962,020, we disclosed a membrane process to capture CO2 from coal power plant flue gas. These processes use combustion air as a sweep stream in a membrane contactor. The air sweep strips CO2 from the flue gas and recycles it back to the boiler. By selectivity recycling CO2, the concentration of CO2 in the flue gas is increased, making its separation much easier. These processes were subsequently applied to gas turbine power plants, such as in U.S. Pat. No. 8,220,247.
Natural gas turbine power plants are costly, large, and highly optimized machines. The expectation is that only minor modifications to the turbines will be needed so these CO2 separation systems can be retrofitted to existing turbines. However, for new plants, the best hope for major reductions in CO2 capture cost is to integrate the capture processes into the turbine design.
One such integrated process was disclosed in our U.S. Pat. No. 9,140,186, shown here in FIG. 4. An air intake stream, 406, is directed to a first compressor, 401a. A compressed gas stream, 443, is combusted with an incoming fuel gas stream, 416 in combustor, 402. The hot, high-pressure gas from the combustor, stream 417, is then expanded through the gas turbine, 403. The gas turbine is mechanically linked to the first and second compressors, 401a and 401b, respectively, and an electricity generator, 404, by shaft 405. The low-pressure exhaust gas, stream 419, from the gas turbine is still hot and sent to a heat recovery steam generator, 420. This section includes a boiler that produces steam, 421, which can be directed to a steam turbine (not shown). A first portion of the gas exiting the steam generator, stream 425, is routed as feed gas to sweep-based membrane separation step, 426.
Step 426 is carried out using membranes that are selective in favor of carbon dioxide over oxygen and nitrogen. Feed stream 425 flows across the feed side of the membranes, and a sweep gas stream, 428, comprising air, oxygen-enriched air or oxygen flows across the permeate side. The membrane separation step divides stream 425 into residue stream 429, depleted in carbon dioxide as compared to feed stream 425, and permeate stream/sweep stream 430. The residue stream forms the treated flue gas produced by the process. The permeate/sweep stream, 430, containing at least 10 vol % carbon dioxide, is withdrawn from the membrane unit and is passed to compressor 101a to form at least part of the air intake stream, 406, to first compression step 101a. 
A second portion of the turbine exhaust, stream 445, is directed to second compressor 401b. The second compressed stream, 444, is then directed to a gas-membrane separation step, 412. Step 412 uses molten salt membranes, 446, which are selective to carbon dioxide over oxygen and nitrogen, to separate the second compressed stream, 444, into a carbon dioxide-enriched permeate stream, 413, and a carbon dioxide-depleted residue stream, 414. Step 412 removes anywhere between at least 50% to 80%, or even 90% of the generated carbon dioxide from the combustor. High levels of carbon dioxide removal by step 412 are not required because residue stream 414 is not vented to the atmosphere, but sent back to the turbine, 403.
One disadvantage of this design, however, is that the compressed air being feed into the gas separation unit is extremely hot, at about 500° C. As a practical matter, this limits the CO2 permeable membranes, 446, to very expensive inorganic materials, such as ceramics or zeolites, which can withstand high temperatures. If more readily available and lower cost polymer membranes are to be used, massive amounts of cooling of the feed gas to bring the gas to the 30-100° C. range is required.
Therefore, it would be beneficial if an integrated gas separation-turbine process were developed that was more economical for CO2 separation.